ARC ENERGY TRUST ANNUAL REPORT 2005
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PROVEN PAST. PROM ISING FUTURE.
Suite 2100, 440 - 2 Avenue SW, Calgary, Alberta, Canada T2P 5E9 1-888-272-4900 (403) 503-8600 www.arcenergytrust.com
2005 AN N UAL R E PORT
4OTAL 2ETURN 0ERFORMANCE 3INCE )NCEPTION PER CENT
!2# %NERGY 4RUST 2OYALTY 4RUST )NDEX
438 0RODUCERS )NDEX 438 #OMPOSITE )NDEX
Message to Unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 10 Themes for 2006 Commodity Prices. . . . . . . . . . . . . . . . . . 8 Promising Future - Enhanced Oil Recovery . . . . . . . . . . . . . .10 Review of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Health, Safety and Environment . . . . . . . . . . . . . . . . . . . . . . . .18
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20 Management’s Discussion and Analysis . . . . . . . . . . . . . . . . .28 Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .51 Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . .55 Notes to Consolidated Financial Statements . . . . . . . . . . . . .58
Since inception our message and our mission have been consistent: utilize our excellent managerial and technical expertise to maximize value to our unitholders. We have done this through the acquisition and development of a portfolio of high quality, long-life assets. We have built a team that has the skills required to manage and exploit our asset base for the benefit of our unitholders.
ARC Energy Trust, located in Calgary, Alberta is one of Canada’s largest conventional oil and gas royalty trusts. As an operating oil and gas company structured as a royalty trust, we acquire and develop long-life, lower declining oil and gas properties in western Canada. Our unitholders receive a monthly cash distribution from the Trust’s producing oil and gas assets owned by ARC Resources Ltd.
PROMISING FUTURE ARC WILL CONTINUE TO MANAGE ITS BUSINESS TO PROVIDE UNITHOLDERS WITH SUPERIOR RETURNS OVER THE LONG-TERM.
This 2005 Annual Report contains forward-looking statements that may be identified by words like “outlook,” “estimates” and similar expressions. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Actual results could differ materially as a result of changes to ARC’s plans, the impact of changes in commodity prices, general economic, market and business conditions as well as production development and operating performance and other risks associated with oil and gas operations. 1
ARC ENERGY TRUST 2005 FINANCIAL HIGHLIGHTS Year ended December 31
1,165,197 6.10 56.75 639,511 3.35 31.15 356,935 1.90 376,566 1.99 59% 578,086
901,782 4.85 43.32 448,033 2.41 21.58 241,690 1.32 329,977 1.80 74% 264,842
23,282 173,800 4,005 56,254
22,961 178,309 4,191 56,870
61.11 8.96 56.54
47.03 6.78 43.13
56.75 (0.70) (11.46) (6.93) 37.66
43.32 (0.71) (8.51) (6.71) 27.39
FINANCIAL (Cdn$ thousands, except per unit, per boe and per cent amounts)
Revenue before royalties Per unit (1) Per boe (5) Cash flow (2) Per unit (1) Per boe (5) Net income Per unit (8) Cash distributions Per unit (8) Payout ratio Net debt outstanding (3) OPERATING Production Crude oil (bbl/d) Natural gas (mcf/d) Natural gas liquids (bbl/d) Total (boe/d) (5) Average prices Crude oil ($/bbl) Natural gas ($/mcf) Oil equivalent ($/boe) (5) Netback ($/boe) (5) Commodity and other revenue (before hedging) Transportation costs Royalties Operating costs Netback (before hedging) (1) (2)
Per unit amounts are based on weighted average units plus units issuable for exchangeable shares at year end. Management uses cash flow to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Cash flow as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital and expenditures on site restoration and reclamation. The net debt outstanding excludes amounts related to commodity and foreign exchange contracts.
Year ended December 31 RESERVES (7)
2005 Gross Reserves
Proved reserves Crude oil and NGLs (mbbl) Natural gas (bcf) Total oil equilavent (mboe) Proved plus probable reserves Crude oil and NGLs (mbbl) Natural gas (bcf) Total oil equivalent (mboe) FINDING, DEVELOPMENT AND ACQUISITION COSTS ($/boe) (6) Including Future Development Capital Current year Three year average Excluding Future Development Capital Current year Three year average TRUST UNITS (thousands) Units outstanding, end of year Units issuable for exchangeable shares Total units outstanding and issuable for exchangeable shares, end of year Weighted average units (4)
Company Interest Reserves
129,169 582.6 226,273
129,745 595.7 229,033
95,734 589.4 193,973
162,695 726.6 283,795
163,385 741.7 286,997
123,226 724.5 243,974
27.58 16.55 26.49 656
17.98 13.50 17.90 420
TRUST UNIT TRADING STATISTICS (Cdn$, except volumes) based on intra-day trading
High Low Close Average daily volume (thousands) (4) (5)
(6) (7) (8)
Excludes exchangeable shares. Barrels of oil equivalent (boes) may be misleading, particularly if used in isolation. In accordance with NI-51-101, a boe conversion ratio for natural gas of 6 mcf:1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. References to boes throughout this annual report are based on a conversion ratio of 6:1. Based on proved plus probable company interest reserves before royalties. Gross reserves include the company working interest before deduction of royalty obligations and do not include royalty interests. Company interest reserves are the company interest plus the royalty interest prior to the deduction of royalty obligations. Per unit amounts (with exception of per unit distributions) are based on weighted average units.
M ESSAG E TO U N ITHOLDE RS
MESSAGE TO OUR UNITHOLDERS On July 11, 2006, ARC will celebrate its 10th anniversary. Investors who participated in that original $10 initial public offering have received $16.23 per unit (including the January 15, 2006 distribution) in distributions and have seen their units appreciate in price to $26.49 on December 31, 2005, which represents a compound annual return of 28 per cent over nine and one-half years. We have seen our production base grow from 9,566 boe per day in 1996 to 56,254 boe per day in 2005 and our employee count grow from just a handful at inception to the 305 we have today. With our history of proven performance we have delivered exceptional value to our unitholders; more importantly, we believe that the assets we have accumulated and the opportunities that exist for material incremental value creation within those assets have positioned ARC for an even more promising future. Since inception, we have believed that high quality, long-life assets should comprise the core of our portfolio. Some of the first assets that helped create the Trust are in the Pembina area in Alberta, an area well known for these key attributes. Building upon this solid foundation, ARC’s evolution into a technically oriented oil and gas producer truly began with the acquisition of Startech Energy in 2001 and was solidified with the acquisition of Star Oil and Gas Ltd. in 2003. ARC’s most recent 2005 acquisitions of assets in the Pembina and Redwater areas continue this legacy and perfectly fit ARC’s criteria to acquire assets with significant upside potential that time, technology enhancements and a positive commodity price environment will allow us to capitalize on. During 2005, ARC’s unitholders enjoyed the most profitable year in the Trust’s history, with an annual total return of 62 per cent – the second highest return in the conventional oil and gas trust sector. This stellar performance was due in no small part to record oil and natural gas prices during the year. The price of West Texas Crude (“WTI”) oil traded in a range of US$41.60 per barrel to an unprecedented high of US$70.50 per barrel and averaged US$56.61 per barrel during 2005.
North American natural gas traded in a range of Cdn$5.90 per GJ at AECO to Cdn$14.00 per GJ during the year and averaged Cdn$8.36 per GJ. This strong commodity price environment resulted in an average total return in the sector of 37 per cent. The fact that ARC’s performance exceeded the sector average by 60 per cent indicates that something beyond commodity prices accounted for our stellar performance. Last year marked a major milestone in the evolution of the Canadian royalty trust and income fund sector when Standard and Poors announced that royalty trusts and income funds would become eligible for inclusion in their benchmark index. This opened the door for significant incremental institutional interest in the sector. For a sector that has traditionally traded on yield, the focus has shifted as this new group of investors are concerned with quality of assets, cost structure and management expertise. In each of these areas, ARC stands tall. In the second quarter of 2005, a leading independent research firm ranked ARC as number one in terms of asset quality among large cap trusts. This ranking was re-affirmed in a January 2006 updated review of the sector. ARC’s market performance in 2005 reflected the recognition of ARC as one of the leading trusts in the sector, regardless of which measure one uses to make such an assessment. The impact of high commodity prices was clearly evident in the Trust’s financial results for 2005. Revenue before hedging was $1.17 billion, cash flow totaled $640 million, distributions were $377 million and net income was $357 million, all new records for the Trust. There are many implications to this record cash flow environment for the Trust and the industry as a whole. Utilization rates measuring the availability of people, equipment and rigs are running at all time high rates, stretching the oil and gas industry to its limits. The well count for the Canadian oil and gas sector reached an all time high of 21,999 well completions. With utilization rates at all time highs, costs are escalating significantly across the sector. Despite these
M ESSAG E TO U N ITHOLDE RS
upward cost pressures, ARC’s operating costs in 2005 were $6.93 per barrel of oil equivalent, an increase of just 3.3 per cent from 2004. This is a significant achievement when considering service and supply costs increased between five and 20 per cent for many of the services ARC utilizes in the field.
Economic Environment Forecasts for commodity prices from analysts and economists of major banks remain bullish for 2006 for various reasons and it appears that we can expect another eventful year with regards to energy prices. Various economic, weather related and geo-political factors kept the markets jittery and quick to react to news in 2005, and we expect the same in 2006. All of the uncertainties that can affect crucial oil and gas supply around the globe have raised the threshold for oil prices so that US$50.00 WTI has become an acceptable norm and prices below that level would most likely be unsustainable. Following this Message to Unitholders, we provide a list of 10 factors that we believe will be important themes influencing commodity prices in 2006.
Acquisitions On December 6, 2005, ARC announced two major long-life asset acquisitions along with an accompanying equity financing. ARC purchased shares in wholly owned subsidiary companies of Imperial Oil Resources and ExxonMobil Canada Energy that owned a 45.57 per cent working interest in the North Pembina Cardium Unit (“NPCU”) and of Imperial Oil Resources that owned a principal interest in the Redwater oil field in central Alberta. ARC funded these acquisitions initially with debt and then repaid a portion of the debt with the proceeds of the equity offering. The assets purchased are legacy assets that comprise two of the largest light oil fields in western Canada. To date, over a billion barrels have been recovered from these fields and ARC estimates 900 million barrels remain unrecovered – approximately 500 million barrels attributable to ARC.
The acquired assets fit ARC’s profile perfectly. They are longlife, light oil assets with potential to add to ARC’s production for the long-term. The assets have a 20 year reserve life index and have increased ARC’s reserves by approximately 16 per cent and reserves per unit by approximately 10 per cent. The Trust’s proved plus probable reserve life index has increased 5.7 per cent to 12.9 years, the longest in our history. The Pembina NPCU asset is in an area that ARC knows well. Over the years, ARC has amassed large holdings in the area - when ARC was formed in 1996, it began its operations with ownership in properties in the Pembina field. Nine years later, the Berrymoor Cardium Unit, the MIPA blocks, and the Lindale Cardium Unit are still key properties for ARC. Earlier in 2005, ARC purchased additional interests in the Berrymoor Unit and the Buck Creek property and ARC now operates all of its principal assets in the Pembina field. Over the years, ARC has proven its ability to extract incremental value in the Pembina area. The acquisition of the NPCU interest enhances our interest in this oil producing area and provides for a promising future. ARC now has a resource base of over 750 million barrels of light and medium oil that is not expected to be recovered under current plans. None of this resource is currently reflected in our reserves estimates. Time, commodity prices and developments in technology will all play a role in determining how much of this oil will ultimately be recovered. A large percentage of this resource is in Redwater, Pembina and southeastern Saskatchewan – all areas that we believe to be amenable to the application of enhanced recovery techniques such as CO2 miscible floods to recover additional oil from our resource base. Two of the largest CO2 floods in Canada are at the Weyburn and Midale oil fields in Saskatchewan; ARC has an ownership interest in both these fields and will be actively looking to apply its learned expertise from these fields to other assets where CO2 recovery techniques may prove beneficial. In particular, we believe Redwater is a prime candidate for a
M ESSAG E TO U N ITHOLDE RS
CO2 flood and was acquired with that future potential as a primary consideration. It is important to note that ARC did not include any value for CO2 upside potential in the acquisition economics for these properties. The acquisition metrics were based on the production currently associated with these fields and any future upside associated with enhanced recovery techniques will be a direct uplift to ARC. The implementation of a CO2 flood and an associated increase in production from Pembina and Redwater will take time – perhaps three to five years or longer; however, ARC has always been a long-term thinker regarding its assets and these projects are expected to play a significant role in our future.
Risk Management We have always believed that protecting the stability of our distributions is very important. ARC began executing a new hedging strategy in late 2004 that primarily focused on the purchase of puts to minimize ARC’s downside on a portion of its production, while providing full participation in price increases. Through this strategy, ARC’s hedging cost will be no higher than the premium paid for these transactions, which is known when it enters into the contracts. ARC believes that this strategy is like buying insurance – it protects a portion of ARC’s production from any unexpected downside that could materialize over the course of a year due to world events beyond its control, but leaves that production open to the full upside in the event of material upward price spikes. Though ARC did collapse most of its fixed hedge contracts in late 2004, it still had a few contracts in place that were capped transactions at a fixed price considerably below 2005 prices and as a result ARC incurred cash hedging losses of $87.6 million. These large losses are behind ARC as it carries on with its current hedging strategy, which allows ARC to participate in price upside on its production. The one exception to this strategy is a three-way collar transaction which will remain in effect through 2009 on 5,000 boe per day of production associated with the NPCU and Redwater 6
acquisitions that limits ARC’s full participation in price increases to US$90 but provides downside protection at US$55.00. The average cost of this price protection over the life of the contract is US$0.91 per barrel. This was done to protect the projected returns from this acquisition as the acquired production carries materially higher operating costs than our base production and we believe that it is important to protect the price and hence our returns over the next four years.
In Memoriam I acknowledge with much regret and sadness that ARC lost an important member of its Board of Directors in 2005. Mr. John Beddome passed away on May 10, 2005. He was a member of ARC’s Board since inception and contributed his wealth of knowledge and experience in the oil and gas industry to ARC and the community at large. His contribution to ARC’s Board will be missed.
New Board Member ARC is pleased to have added Mr. Herb Pinder to its Board of Directors effective January 1, 2006. Mr. Pinder brings an extensive business background to ARC covering several industries and a broad knowledge of corporate governance gained through his experience as a director on various public company boards over the last 20 years. Mr. Pinder holds a Bachelor of Arts degree from the University of Saskatchewan, an LL.B from the University of Manitoba and an MBA from Harvard University Graduate School of Business. Currently, Mr. Pinder is the President of the Goal Group, a private equity management firm located in Saskatoon, Saskatchewan. I know Mr. Pinder will make a strong contribution to ARC and I look forward to working closely with him in the future.
10 THEMES AFFECTING COMMODITY PRICES IN 2006 These are 10 themes that we believe will shape the world’s energy markets in 2006. How these themes play out will have a large impact on commodity prices during the year.
1. Renewed emphasis on demand growth. Ever since hurricanes Rita and Katrina struck and momentarily pushed oil prices over $70.00 per barrel the market has been concerned about on demand growth for petroleum products. Now there is growing acknowledgment that the world’s economy can handle oil prices above $50.00 per barrel, or more. Asian economies like China and India are still growing aggressively and requiring increasing amounts of energy commodities to do so. This will not change appreciably in 2006. Nor will the growing appetite for petroleum—especially gasoline—change in the United States.
2. More flexing of NOC muscle. National oil companies (“NOCs”) control the vast majority of the world’s oil and gas reserves. From Iran, to Venezuela, to Russia, state-controlled oil companies are more and more being used as extensions of the host government’s policy and power. We should expect the use of oil and natural gas as a state-directed tool of influence to grow in 2006. Supply side NOCs see two broad objectives: (1) to use critical energy supplies as a means to achieve political aims; and (2) to extract as much economic value out of the commodities as possible. Russia’s dispute with the Ukraine is the most recent example of how critical energy resources are being used to exert muscle and raise prices. The new Bolivian government is seeking to nationalize its large natural gas reserves, nullifying long-standing contracts, and imposing tighter fiscal regimes (i.e. higher prices) on its natural gas exports. OPEC countries are not alone in using energy commodities as tools to project national influence. It’s not new that NOCs control much of the world’s oil and gas. What is new is that a tight supply and demand balance allows even marginal players to exert substantial leverage on the consuming world.
3. Iran becomes a flashpoint. Iran’s Prime Minister has been very overt about his nation’s nuclear ambitions. The prospect of an atomic Iran has western governments feeling very jittery. The prospect that Iran, a major oil and natural gas supplier, will turn into a geo-political flashpoint is a “known unknown.” At 3.9 million barrels per day, Iran is the fourth largest producer of oil in the world. That’s 8
notable enough, but more importantly Iran controls the northern side of the Strait of Hormuz, the 50-kilometre-wide waterway through which flows almost 20 per cent of the world’s daily oil supply. Kuwait, Iraq, Iran, Saudi Arabia, Bahrain, Qatar, all transport much of their oil through this choke point. In addition, Iran boasts the second largest natural gas reserves in the world, after Russia. Iran has publicly stated that it will use its oil supplies as a potential lever in the current nuclear standoff.
4. Increasing recognition of concentration risk. Hurricanes Rita and Katrina awoke people to the risks of having too much energy infrastructure located in a concentrated geographic location. The recent Russia-Ukraine spat awoke Europeans of being too dependent on a big supplier. With the supply and demand balance for oil remaining tight through 2006 and beyond, markets will be increasingly sensitive to concentration risk; in other words, this year there will be a heightened awareness that too much critical energy supply or infrastructure is located in too few places.
5. Shortfall in oil production growth expectations. Some influential agencies and consulting firms are calling for non-OPEC supply additions to add up to 1.4 million barrels per day this year. That’s an aggressive number, given that achieving one million barrels per day has been difficult over the past several years. As well, over half the non-OPEC additions in the past three years have come from Russia. The Russians have publicly stated that their production growth has fallen to two per cent, or about 180,000 barrels per day. We think the market is going to be disappointed with how much new, non-OPEC oil comes on line in 2006. Additions may well be only 600,000 barrels per day, instead of the 1.4 million barrels the market is expecting.
6. OPEC will defend $50.00 barrels per day and above. Seasonal factors, like the low-demand second quarter, may momentarily pull oil prices back down into the low-fifty-dollar range. OPEC members will defend $50.00 per barrel as their floor.
Emergence of energy policies in Asia.
Rapidly growing Asian nations like India and China know that they must do something to mitigate their aggressively growing dependency on energy, especially oil. Last year, India’s leadership began discussing a long-term, visionary energy policy. Energy policies have much more influence than market forces in effecting change, especially on the demand side. With prices remaining volatile in 2006, governments will start becoming more visible in addressing energy issues in Asia. But will North American policy makers follow?
8. Narrowing of the global natural gas price arbitrage. In the past one of the biggest energy anomalies in the world has been the huge price gap between expensive natural gas markets, like the US and the UK, and other parts of the world. For example, when the price of natural gas at Henry Hub was $12.00 per mmbtu, in North Africa it was $3.00 per mmbtu. Markets quickly sniff out such ‘arbitrage’ opportunities and work to close the gap. The reason for the price anomalies is that natural gas is difficult to transport across long distances. Without pipeline access or liquefaction facilities, natural gas reserves in low value regions are ‘stranded,’ because the gas can’t get to market. That’s changing with the global construction boom in natural gas pipelines and liquefied natural gas (“LNG”) facilities. Many believe that cheaper natural gas from places like Trinidad, Qatar, Iran and Russia will eventually make it to North America, bringing US and Canadian prices down. There is no question that the arbitrage will eventually narrow as pipelines and LNG facilities are built. But it’s much more likely that global natural gas prices will rise closer to North American prices, not the other way around. Similar to oil, global natural gas resources are heavily concentrated under NOC control, with Russia, Iran and Qatar holding the lion’s share. What is the incentive of such countries to give their natural gas away at lower prices?
disruptions after last fall’s hurricanes caused legitimate concern about natural gas supply in advance of winter, causing the normal WTI-to-Henry Hub price ratio of about 6.5x to narrow to 4.0x. A mild winter so far, combined with disruptions in industrial demand, have led to acceptable levels of natural gas to remain in storage. There may still be some cold spells and large storage withdrawals to come during the remainder of the winter season. Prices will rally and the WTI-to-Henry Hub ratio will narrow. But don’t expect it to last. With oil at $60.00 per barrel, natural gas prices above $10.00 per mmbtu, as we experienced in 2005, are not sustainable.
10. North American gas markets will ‘see’ LNG. There are half-a-dozen LNG receiving terminals that are likely to come on line in North America by the end of this decade. Up to 6 bcf per day of new natural gas will be supplied to our domestic markets. To this point, the time horizon for these facilities has been ‘years away.’ With the first of the facilities likely to come on line in 2007, the reality will start to become much closer for the market to grasp this year. As these new LNG facilities become more ‘visible’ to the market, the forward price curve for natural gas is likely to become more stable, and less influenced by near-term seasonal factors. Cautionary Statement: “10 Themes Affecting Commodiy Prices in 2006” is provided by management of ARC Resources and contains projections, beliefs and other forward looking statements. Such statements are based on assumptions that involve a number of risks and uncertainties, including those referenced in this Annual Report in Management’s Discussion and Analysis. Results may differ materially from such statements for a wide variety of reasons, including geopolitical events, and economic, market and business conditions. Investors should consult their own advisors in relation to any investment decisions.
As long-term contracts expire, the global natural gas arbitrage will narrow over the coming years. And contracts may not mean much. NOCs representing both small and large producing countries have demonstrated their muscle. As they’ve done for oil, they will seek to extract as much value from natural gas as possible. We may see it happen this year.
9. A return to a normal trading ratio for natural gas. In the first couple of months in 2006, the price of natural gas at Henry Hub has fallen by about 45 per cent, down to around $7.00 per mmbtu. Although some are viewing this as a price collapse, we see it as a return to normal. Gulf Coast production
PROMISING FUTURE – ENHANCED OIL RECOVERY Background Conventional oil production techniques only recover a fraction of the original oil in place (“OOIP”), in most circumstances leaving most of the oil still locked in the ground. Depending on the characteristics of the reservoir, initial production methods may only recover five to 20 per cent of the OOIP. Secondary recovery methods, such as injecting water into the reservoir may recover an additional 10 to 20 per cent, but still leave much of the oil behind. Oil companies have been searching for years for other techniques to get more of this valuable resource out of the ground. One of the techniques used is “miscible flooding.”
Miscible Flooding A miscible flood is a general term for recovery techniques that inject gases or liquids into a reservoir under such conditions that the injected materials dissolve into the oil. This changes the characteristics of the oil in the ground helping to break the bonds that trap the oil in the rock pore spaces thereby increasing the amount of oil that can be recovered. Typical injected liquids and gases include liquefied petroleum gas (such as ethane and propane), nitrogen under high pressure, and carbon dioxide (CO2) under suitable reservoir conditions of temperature and pressure. In the United States, the most commonly used substance for miscible displacement is carbon dioxide because it is readily available at a lower cost than liquefied petroleum gases. There are naturally occurring sources of CO2 in Colorado that provide a low cost supply for the CO2 flooding of oil fields. CO2 miscible floods have been ongoing in the United States for more than 30 years with over 60 projects in operation today.
Canada In Canada, where there are no large scale naturally occurring sources of high quality CO2, most miscible floods have used liquefied petroleum gases, but as these have increased dramatically in price in recent years, oil and gas companies have looked for cheaper alternatives. The first large scale CO2
miscible flood in Canada was the Weyburn field in southeast Saskatchewan. CO2 flooding of this field started in 2000 and is expected to recover an additional 10 per cent of the OOIP. In 2005, CO2 flooding started at a neighbouring field called Midale. Both of these fields have been developed because a low cost source of CO2 is available as the US government provided subsidies to North Dakota Power to capture the CO2 emissions from a coal gasification facility. ARC has a seven per cent working interest in the Weyburn field and a 15.5 per cent working interest in the Midale field.
ARC’s Future Potential From inception, ARC has focused on obtaining assets that have large unrecovered resources. In addition to our interest in the Weyburn and Midale fields, we have other fields in Saskatchewan that also may be amenable to CO2 flooding. In Alberta, ARC is the largest working interest owner in some of the most favourable areas in the Pembina field for this application. In addition, ARC believes that the recently acquired Redwater field is also a promising candidate for enhanced recovery through CO2 injection. In total, ARC believes that between five and 15 per cent of the two billion barrels of OOIP in the Pembina and Redwater fields that ARC has an interest in may eventually be recovered should the right economic conditions exist.
What’s Required? For large scale CO2 miscible flooding to occur in Alberta, a commercially viable source of CO2 must be developed along with the associated pipeline infrastructure to transport the CO2 to the applicable oil fields. As no naturally occurring sources are available, the most likely source will be to capture the CO2 that is currently emitted by upgraders, refineries, petrochemical plants, coal fired power plants and other large industrial sources.
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REVIEW OF OPERATIONS A substantial portfolio of high quality, long-life assets has consistently provided ARC with a large inventory of development opportunities. ARCâ€™s focus on opportunistically acquiring assets that have additional development potential embedded in them has proven itself time and time again. ARC has identified drilling and development opportunities within its asset base that are expected to sustain its production for the next 12 to 18 months and possibly longer, without being reliant on acquisitions. Proved Plus Probable Reserves
2005 Average Production
% of Total Production
22,350 50,540 83,398 45,682 57,432 24,393
22,665 51,872 84,433 45,733 57,899 24,395
7.9 18.1 29.4 15.9 20.2 8.5
8,041 11,298 18,286 10,676 7,789 164
14.3 20.1 32.5 19.0 13.8 0.3
For 2005, ARC averaged 56,254 boe per day of production, with 51 per cent coming from natural gas. Production increased during the year from 55,410 in the first quarter through to 59,120 in the fourth quarter as a result of ARCâ€™s capital development program and several key acquisitions. Production averaged over 61,000 boe per day during the month of December. % of Total Proved plus Probable Reserves
Area Central Alberta SE Alberta/SW Saskatchewan Northern Alberta & BC SE Saskatchewan Pembina Redwater (1)
Proved Plus Probable Reserves
(1) Redwater was acquired December 16, 2005. The December 2005 exit rate was 3,749 boe per day.
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